In order to improve the efficiency of extracting hydrocarbons from subterranean formations, it is known to inducing and/or extend existing fractures and cracks in the subterranean formation. Fractures may extend many meters and tens or even hundreds of meters from a main wellbore from which they originate.
As hydrocarbon-bearing formations are often disposed substantially horizontally, in many cases it is preferred to use horizontal drilling and fracking operations (inducing fractures in the formation) may be carried out on a single well. This may be accomplished by, for example, retracting open slots in an liner along the borehole. A common method to induce fractures is by hydraulic fracturing. In this case, a fluid is pumped into the formation via the wellbore at high pressures. The pressure can be up to around 600 bar. The first fractures may be created by the use of explosive materials, and these are extended by the high pressure fluid. The most commonly used fracking fluid is water with added chemicals and solid particles. Typically the solids, termed proppants, make up 5-15 volume % of the fracking fluid, chemicals make up 1-2 volume % and the remainder is water.
Other fracking fluids include freshwater, saltwater, nitrogen, CO2 and various types of hydrocarbons, e.g. alkanes such as propane or liquid petroleum gas (LPG), natural gas and diesel. The fracking fluid may also include substances such as hydrogen peroxide, propellants (typically monopropellants), ac ids, bases, surfactants, alcohols and the like.
Once area of interest is improving recovery beyond primary depletion for tight oil reservoirs, and in particular what are often referred to as shale oil reservoirs. Shale oil reservoirs primarily comprise liquid hydrocarbons in a low permeability formation. Owing to the low permeability, oil production from shale oil reservoirs is improved by fracturing the formation to provide paths of enhanced permeability along which hydrocarbons can flow. Operators have begun to develop what were previously uneconomic assets using a combination of hydraulic fracturing and long horizontal wells. However, while these can give promising initial yields, production rates from primary depletion often dramatically decline, yielding only a small fraction of the initial production rate after several years. Moreover, primary depletion only recovers a fraction of the Original Oil in Place (OOIP); typical recovery factors for some assets are often assumed to be on the order of 5-15%. These shortcomings are due to the low permeability of the reservoirs and the lack of a sufficient drive mechanism which, in the case of primary depletion, is often reservoir compaction and oil volume expansion.
Some operators have considered water-flooding to enhance production, but the oil-wet to mixed-wet nature of the target reservoirs, the low relative permeability to water, and injectivity/plugging issues have often made traditional water-flooding techniques unattractive in shale oil reservoirs.
Gas flooding has shown more promise as an Enhanced Oil Recovery (EOR) method for shale oil reservoirs. Gas floods in these reservoirs are often miscible and can provide additional forms of drive mechanisms including pressure support, oil swelling, and gravity drainage. Several gas flooding pilots have been carried out, but no known commercial developments have commenced in the largest shale oil reservoirs because the pilots have experienced challenges. The foremost challenge these pilots have experienced is rapid channeling from injectors to producers. The cause of this rapid channeling is uncertain but often attributed to some form of natural or induced fracture network. It is well known that during hydraulic stimulation of some of these wells, fluid communication can occur with adjacent wells. The entirety of every hydraulically stimulated fracture may not be propped, but after a fracture in a rock is created, lab experiments show they have potential to have significantly higher permeability than the surrounding matrix or unstimulated rock volume typically found in shale oil reservoirs, particularly under lower effective stresses, as would be experienced under gas injection. These stimulated zones may contribute toward the rapid communication between injection wells and production wells that has been observed in previous field tests, resulting in gas channeling, and uneconomic gas floods.
Another key challenge is the low matrix permeability, which necessitates short flooding distances or higher pressure gradients to achieve economically attractive flood durations. Some technologies have been proposed to reduce the distance that fluid must travel, such as flooding between transverse fractures from two wells placed in close proximity to one another. However, this solution is potentially expensive (as it requires one well which does not contribute effectively to primary production), and it does not address the issue of rapid channeling due to fractures. To reduce costs, it has been proposed that flooding between adjacent fractures is carried out in a single well; however, the completions challenges associated with this concept are significant, particularly for ultra-tight reservoirs with horizontal wells, which often utilize dozens of fracture stages and small diameter liners in the pay.
Additional solutions have been proposed of plugging fractures with various injectants such as polymers or gels. However, very little is known about how those plugging agents would impact ultra-tight formations (e.g., what the affect would be on matrix pore plugging, how these plugging agents would transport through the fracture system, and how effectively they could block off the entire fracture system).